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Appendix D: Modelling summary

Table of contents

Appendix D.1. Introduction

The Authority engaged SKM MMA to undertake electricity market modelling to assess the potential impacts of changes to the current Renewable Energy Target (RET) scheme on the electricity generation capacity mix and production, emissions abatement, certificate prices, resource costs, wholesale and retail electricity prices and power bills for the average household and small to medium enterprises (SMEs).

updated 20 per cent target of 26 400 GWh in 2020 for large-scale renewable generation to reflect downward revisions to long term electricity demand forecasts, allowing for around 11 000 GWh for the contribution of Small-scale Renewable Scheme (SRES) technologies - updated 20% target; and

rolling the LRET and SRES back into one target of 45 000 GWh in 2020, to occur from 1 January 2015 - combined LRET & SRES.

This appendix summarises reference case 1 results compared with no RET and updated 20% target scenarios. Detailed results and assumptions for all scenarios are outlined in the SKM MMA modelling report available at the Authority's website.

The results should be interpreted as what might happen given a set of assumptions and scenarios rather than predicting future outcomes. Indeed, the modelling exercise is based on existing regulatory and policy settings, which may change in the future.

The modelling period for the analysis was from 2012-13 to 2040-41 to ensure investments which are forecast to occur following 2020-21 take into account future revenues over the life of the investment. Reporting of results in this appendix focuses on the period 2012-13 to 2030-31.

Modelled impacts of scenarios on retail and SMEs electricity prices reported in this appendix include a suppression of wholesale prices. An analysis of impacts excluding wholesale price suppression can be found at Chapter 4.

All values from the modelling are denominated in June 2012 prices.

Where a net present value is provided, a discount rate of seven per cent has been used, consistent with recommendations from the Office of Best Practice Regulation (2010).

Appendix D.3. Modelled carbon price scenarios

The Authority has drawn on two of the Treasury carbon price scenarios published in Strong Growth, Low Pollution: modelling a carbon price 2011 (SGLP) and the SGLP Update as points of reference for its modelling. A zero carbon price scenario was also modelled. Each of the three scenarios is described in greater detail below and illustrated in Figure 29.

CP1(Reference case 1) - Combines the Treasury SGLP Update $23 scenario and Treasury SGLP 'low starting price' scenario. This scenario assumes a nominal domestic price of $23 per tonne of carbon dioxide equivalent (CO2-e) in 2012-13 rising on average 2.5 per cent per year plus inflation over three years. The scenario assumes a transition from this price path to a fixed price of around $12 per tonne of CO2-e in 2015-16 (this fixed price is consistent with the Treasury SGLP 'low starting price' scenario), which was part of a sensitivity analysis that assumed a domestic fixed price of $10 per tonne of CO2-e in 2012-13 rising five per cent per year plus inflation over a fixed price period of ten years. This Treasury scenario assumed a transition from a fixed price of around $19 per tonne of CO2-e in 2021-22 to an internationally linked scheme with a forecast global carbon price of around $49 per tonne of CO2-e in 2022-23.

CP2 (Reference case 2) - Assumes a world with a 550 ppm stabilisation target and an Australian emissions target of five per cent cut on 2000 levels by 2020 and 80 per cent cut by 2050. This assumes a nominal starting price of $23 per tonne of CO2-e in 2012-13, rising 2.5 per cent per year, plus inflation, before moving to a flexible international carbon price from 2015-16, projected to be around $29 per tonne of CO2‑e. This scenario was published by the Treasury in the SGLP Update.

CPO (Zero carbon price) - Assumes a nominal domestic starting price of $23 per tonne of CO2-e in 2012-13 rising on average 2.5 per cent per year plus inflation over three years, falling to zero from
July 2015.

Appendix D.4. Key sensitivities

The implications of a change in either carbon price or demand

The modelling results are particularly sensitive to assumptions relating to future carbon prices and electricity demand.

The Authority's modelling explored whether the target under reference case 1 would be met if the carbon price fell to zero (zero carbon price scenario) or if demand were significantly lower than currently forecast (low demand scenario). The modelling suggests that if either the carbon price went to zero or electricity demand fell further than is currently forecast by AEMO, then there is a greater likelihood that the LRET target would not be met because overall wholesale prices would be lower, requiring higher certificate prices for renewable energy projects to be viable. Figure 23 in Chapter 4 indicates:

the shortfall charge is estimated to come into play in the zero carbon price scenario, in which case the LRET would not be met as liable parties are likely to pay the shortfall charge rather than meet their LRET obligations - a result that is consistent with the findings of other modelling exercises (for example, AEMC 2011); and

in the low demand scenario the LGC price is estimated to remain below the shortfall charge, although between 2020-21 and 2021-22 the LGC price comes close to hitting the shortfall charge which averages around $74 over this period.

Estimating the cost of abatement

The Authority has used the Department of Climate Change and Efficiency (DCCEE) methodology for estimating the cost of abatement. The DCCEE methodology uses the following formulae and uses discount rates consistent with recommendations from the Office of Best Practice Regulation (2010).Further detail can be found on the Estimating Cost publication.

Key estimated impacts

The following section summarises the key estimated impacts of the different target scenarios on:

The existing target, however, accelerates the build of new renewable energy generation (primarily wind) in the period to 2020-21 during which the carbon price is insufficient to make the development of new renewable energy generation economically viable (see Figure 30). By the end of 2020-21, it is estimated that around 13 875 MW of new renewable energy generation capacity will be installed compared with around 5 043 MW under the no RET scenario.

Figure 31 presents an overview of total generation in gigawatt hours by broad fuel category and shows the increasing share of renewable energy generation under reference case 1. The share of total generation from renewable energy (including an allowance for a reduction in demand due to displacement technologies) is forecast to grow from around 14 per cent in 2012-13 to around 25 per cent in 2020-21 and remain at this level in 2030-31. By comparison, under the no RET scenario it is estimated that renewable energy generation contributes around 13 per cent in 2012‑13, around 15 per cent in 2020-21 and around 25 per cent in 2030-31.

Additional renewable energy generation displaces some fossil‑fuel generation over the period modelled but the overall results for individual fuels are mixed. Over the period 2012-13 to 2030-31, for reference case 1, output from black-coal fired generation is estimated to increase by around 24 000 GWh while brown-coal fired generation is expected to decrease by around 3 800 GWh.
Coal-fired generation remains relatively competitive with gas-fired generation over this period as real gas prices in the southern and eastern states are assumed to double by 2030-31 as they approach international price-parity levels. Brown coal-fired generation capacity is not estimated to change substantially until after 2030-31, when retirement of some brown coal-fired generation is anticipated.

Figure 32 provides an estimate of the share of generation delivered by eligible renewable energy plant of different technology types. It shows that most of the additional renewable energy generation is likely to come from wind (32 433 GWh in 2020-21), with a smaller contribution from solar PV (large-scale PV generation of 1 288 GWh and small-scale PV generation of 7 933 GWh in 2020-21). Even though the carbon price is assumed to be increasing, a corresponding increase in large-scale renewable generation is not expected because neither the large-scale certificate price nor the carbon price are high enough to encourage new investment. In addition, solar water heating is treated in the modelling as an offset to demand, but its contribution is not assumed to materially change from its existing contribution in the period to 2030-31.

Emissions from the electricity sector

Total emissions from the stationary electricity sector over the period 2012-13 to 2030-31 are estimated to be around 3 570 Mt of carbon dioxide equivalent under the reference case 1 scenario. It is estimated that emissions will fall over the period 2018-19 to 2020-21, reflecting increased wind generation displacing existing fossil‑fuel generation. However, over the period 2012-13 to 2030-31 annual emissions are estimated to increase by nine per cent. The growth in emissions occurs because, with the renewable energy target having been met, renewable generation levels are stable from 2020-21 and fossil-fuelled generation meets any electricity demand growth through the remainder of that decade. By comparison, under the no RET scenario, total emissions over the period 2012-13 to 2030‑31 are estimated at around 3 787 Mt of CO2-e.

Cost to society

To understand the RET's effect on the overall cost to society, the cost of resources (capital, fuel and labour) deployed in electricity generation with and without the RET have been estimated. This approach has been taken because it is likely that in the absence of a RET that capital and operational expenditure on other generation sources will be required.

New renewable and gas-fired capacity installed over the period 2012-13 to 2030-31 to meet LRET and SRES obligations and electricity demand requirements is estimated to come at a resource cost of around $142 billion in net present value terms - noting that total resource costs represent annualised capital expenditure plus the change in overall system operating costs including reductions in fossil‑fuels used. Under the no RET scenario, total resource cost over the same period is estimated to be around $134 billion in net present value terms, 76 per cent of which is directed at investment in the fossil‑fuel sector (see Figure 33). As such, the modelling indicates that under reference case 1 the RET will generate an additional $8.6 billion of resource investment (in net present value terms) which represents around a six per cent increase in resource costs over the period to 2030-31 when compared to the no RET scenario.

Figure 33: Contribution to total resource costs over the period 2012-13 to 2030-31Source: SKM MMA and Climate Change Authority, 2012.

Cost to households and businesses

Certificate prices

The price of a large-scale generation certificate (LGC) is broadly the difference between the wholesale price of electricity and the additional revenue required to make additional renewable energy generation a financially viable prospect. Bloomberg New Energy Finance (2012) has estimated the LGC price currently required to build new capacity is around $40 to $50. A large number of LGCs are, however, traded outside the spot market in (confidential) power purchase agreements and the effective price of the LGCs is unknown.

The LGC price under the reference case 1 scenario is estimated to remain below the shortfall charge over the period 2012-13 to 2030-31 (see Figure 23, Chapter 4). The shortfall charge is currently not indexed, and its real value falls over time in line with inflation. The LGC price is forecast to approach the tax‑effective shortfall charge by 2019-20, reaching around $65 in that year, as higher cost renewable energy projects need to be developed to meet the annual targets.

It is estimated that all of the new renewable generation capacity required to meet the targets until
2030-31 would be built by 2020-21. Although there is no substantive change in large-scale renewable generation from 2020-21 to 2030-31, other market forces (for example, rising carbon prices, falling technology costs and high gas prices) are estimated to help create an environment where renewable energy development is approaching financial viability from 2030-31 onwards.

Electricity prices

The components of the retail price as modelled include:

wholesale prices;

network charges (which are assumed to represent a fixed cost with some escalation in some states based on anticipated increases);

All other things being equal, the modelling estimates that the higher the large-scale renewable energy target the greater the increase in renewable energy development and the lower the wholesale price.
At the same time, however, there will be a greater number of renewable energy certificates created. The net effect on energy consumer bills will therefore reflect the balance of the change in wholesale costs and change in certificate costs.

Over the period 2012-13 to 2030-31, volume weighted average wholesale electricity prices under the reference case 1 scenario are estimated to rise from $54 per MWh to $120 per MWh (see Figure 34). The substantial upward shift in prices from 2021-22 to 2022-23 ($58 per MWh to $88 per MWh) is, however, the result of the step change in carbon prices that is assumed to occur at that time.

Overall movements in forecast wholesale and retail prices are quite similar under the reference case 1 scenario, although the margin between them grows slightly because of:

increase in RET certificate costs to 2020-21; and

expectations of slight growth in network charges.

The expected differences in the wholesale and retail prices between the reference case 1 and no RET scenarios indicate that with a RET in place, wholesale prices are lower under the reference case 1 scenario but retail prices are higher, reflecting the wedge created by the pass-through of certificate costs (see Figure 35).

Figure 35: Change in wholesale and retail prices - no RET compared with reference case 1Source: SKM MMA and Climate Change Authority, 2012.
Note: A positive number indicates the value is higher in the reference case 1 scenario than in the no RET scenario.

Energy consumer effects

RET certificate costs are estimated to contribute an average of 3.8 per cent of the total retail costs of electricity over the period to 2030-31, which equates to around $70 per annum for the average household electricity bill, assuming annual consumption of 7 MWh (see Figure 36). Higher RET certificate costs in the reference case 1 scenario compared to the no RET scenario are estimated to be largely offset by lower wholesale prices under reference case 1.

The average household electricity bill is estimated to rise through to 2030-31 at an average annual rate of 2.2 per cent under the reference case 1 scenario. The sharpest rise coincides with the step change from 2021-22 to 2022-23 driven by the modelled carbon price. Average household bills are expected to plateau from 2024-25 reflecting lower RET certificate costs.

Average household electricity bills are forecast to be around $15 per annum higher, on average, over the period 2012-13 to 2030-31 compared to the no RET scenario.

Similarly, the average retail price of electricity for an average small to medium enterprise (SME), consuming 140 MWh per annum, is estimated to be slightly higher on average under the reference case 1 and no RET scenarios over the period 2012-13 to 2030-31 (see Source: SKM MMA and Climate Change Authority, 2012.

Figure 37). The average SME bill is estimated to increase by around $335 per annum on average over the period 2012‑2013 to 2030‑31, around $17 (or five per cent) of which is attributable to the RET.
It should be noted that the modelling indicates that SMEs face a proportionally higher RET cost for their electricity bills when compared to the average household due to the fact that SMEs on average face a lower electricity tariff (around $45 per MWh lower than households on average per annum).

Reference case 1 compared to updated 20% target

Generation of electricity from renewable sources

Comparing reference case 1 with an updated 20% target scenario reveals that over the period 2012-13 to 2030-31 there is a similarity in the level of new renewable generation capacity by 2030-31
(see Table 11). However, the existing target accelerates the build of new capacity (primarily wind) in the period to 2020-21, during which the carbon price is insufficient to make renewable energy generation economically viable. By 2020-21, it is estimated that around 13 615 MW of new renewable energy generation capacity will be installed compared with around 9 053 MW under the updated 20% target scenario.

Figure 38 presents an overview of total generation in gigawatt hours by broad fuel category and shows the increasing share of renewable energy generation. As a share of total generation, it is estimated that renewable energy generation (including an allowance for displacement technologies) contributes around 14 per cent in 2012-13, growing to around 20 per cent in 2020-21 rising to around 25 per cent in 2030-31 under the updated 20% scenario. By comparison, under the reference case 1 scenario renewable energy generation (including an allowance for displacement technologies) contributes around 14 per cent in 2012-13, growing to around 25 per cent in 2020-21 and remaining at this level in 2030-31.

Under the updated 20% scenario, in the period from 2012-13 to 2030-31, output from black-coal fired generation is estimated to increase by around 24 940 GWh while brown-coal fired generation is expected to decrease by around 3 750 GWh. Coal-fired generation remains relatively competitive with gas-fired generation over this period as real gas prices in the southern and eastern states are assumed to double by 2030 as they approach international price-parity levels. Brown coal-fired generation capacity is not estimated to change substantially until after 2030, when retirement of some brown coal‑fired generation is anticipated.

Generation capacity and production

Under an updated 20% target scenario, it is estimated there would be substantially less renewable generation capacity installed through most of the period from 2012-13 to 2030-31. By 2021-22 renewable generation capacity would be around 5 000 MW lower than under reference case 1 (see Figure 39). By 2030-31, however, the difference is estimated to be largely eliminated, suggesting that a lower 2020 target delays renewable capacity investment to beyond 2020-21.

With a lower target, generation from renewable sources is estimated to be substantially below the current settings (see Figure 38). At the peak of the differences between the two scenarios in 2021-22, under the updated 20% target:

renewable energy generation is estimated to be around 14 000 GWh less (21 per cent of total renewable energy generation in that year for reference case 1);

black coal-fired generation is estimated to be around 9 500 GWh more (eight per cent of total black coal-fired generation in that year for reference case 1);

brown coal-fired generation is estimated to be around 4 200 GWh more (ten per cent of total brown coal-fired generation in that year for reference case 1); and

gas-fired generation is estimated to be around 1000 GWh more (three per cent of total gas-fired generation in that year for reference case 1).

Cost to society

By transitioning to a lower RET target under the updated 20% scenario, the savings in resource costs is estimated to be around $4.5 billion in net present value terms over the period 2012-13 to 2030-31
(see Table 12). The modelling does not, however, assume any change to renewable development costs that might flow from increased risk premiums associated with renewable energy policy uncertainty.

Table 12: NPV of resource cost ($ million)

Source: SKM MMA and Climate Change Authority, 2012.
Note: The discount rate used for the NPV is seven per cent.

A change in the target not only has an impact on the total investment in the renewable sector but also has a significant impact on investment in the fossil‑fuel sector. As indicated in Figure 40, the proportion of total resource costs in both scenarios is dominated by the fossil‑fuel sector, increasing its contribution to the total resource cost by four per cent in the updated 20% scenario.

2012-13 to 2020-21

2012-13 to 2030-31

Difference between updated 20% target and reference case 1

-2 484

-4 457

Figure 40: Contribution to resource costs over the period 2012-13 to 2030-31Source: SKM MMA and Climate Change Authority, 2012.

Emissions

Total greenhouse gas emissions are estimated to be higher in the updated 20% target scenario when compared to the reference case 1 scenario. As shown in

Table 13, an additional 119 Mt CO2-e of emissions are expected to be generated by moving to a lower, updated 20% target due to the higher levels of generation from fossil‑fuel generation under that scenario.

On a dollar per tonne basis, the updated 20% target represents an abatement cost of around
$38 per tonne compared to $40 per tonne under current settings.

Costs to households and businesses

Wholesale electricity prices are expected to be generally higher under an updated 20% target scenario (see Figure 41). However, there is only a marginal change in retail prices for all energy consumers as the estimated fall in LGC prices (see Figure 42) reduces the required certificate cost pass-through to consumers.

As a consequence of the marginal change in retail prices per unit of consumption, the impact of moving to an updated 20% target on the average household bill is expected to be small. SKM MMA's modelling indicates that moving from current settings to an updated 20% target will deliver an average annual increase in the household bill over the period 2012-13 to 2030-31 of around $0.40 per annum with retail prices averaging around the same level under both scenarios. The modelling indicates that an updated 20% target will deliver a decrease in the household bill of around $0.70 per annum on average over the period 2012-13 to 2020-21 and an increase of around $0.40 per annum on average over the period 2012-13 to 2030-31.

Figure 43 indicates the contribution of the RET to the average household bill over the period to 2030-31 is expected to be lower under the updated 20% target scenario at around $43 per household compared to around $70 per household under reference case 1. However the difference between the total bill cost by 2030-31 is almost zero.

Lowering the target is also not expected to deliver significant savings to the electricity bill of an average SME. The expected retail price under the updated 20% scenario is estimated to be around $0.10 per MWh lower on average over the period 2012-13 to 2030-31 (see Figure 44). This represents an estimated decrease in an average SME bill of around $13 per annum on average over the period.